Pipeline Transportation Out of the Marcellus - No Magic Carpet Ride

When producers like Range Resources entered the Marcellus in 2007, one of the benefits of drilling in the Northeast as opposed to the Rockies was the price upgrade compared to the Henry Hub. Rockies prices had historically been disadvantaged, with wellhead prices averaging a dollar or more below the benchmark, while the Marcellus’ proximity to demand centers meant that gas produced in the area could actually command a premium to Henry Hub. This of course meant more return for every drilling dollar spent in the Northeast instead of the West. [see Location Location Location]

But a funny thing happened along the way. Drilling and therefore production ramped up in 2009-2010, and test after test showed huge potential for unlocking gas reserves under Pennsylvania, West Virginia, and Ohio using modern completions technology. By 2012 and 2013, the region switched from undersupplied to oversupplied, and prices relative to Henry Hub fell dramatically, from premium to substantial discount. In some areas like on (Williams-owned) Transco’s Leidy line and El Paso’s Tennessee Gas Pipeline zone 4 Marcellus, prices traded at times under $1.00/MMBtu in the daily market, a marked discount to the $4.00+ Henry Hub at the time. Other historically strong regional price points such as Dominion South, TETCO M2, and Transco Zone 6 began to slip as well, especially during low-demand times and mild weather.

Producers in the Marcellus suddenly found themselves at a disadvantage, delivering gas into constrained pipelines that had never been built to handle the massive volumes coming into their systems in these areas. The early movers quickly purchased what was left of capacity rights through the constraints, paying for the ability to deliver gas to citygates where demand for the gas would be assured. Next, a flood of proposed projects by pipeline operators attracted commitments from many producers in the area. Some were to expand capacity to reach valuable New England markets. Some were to reverse traditional pipeline flows to allow delivery to the Gulf coast, and guarantee price at the Henry Hub benchmark by physically delivering to it (not to mention access future exports). Others were a combination of new construction and pipeline expansion to allow access to Midwest demand centers.

While the rapid and large-scale infrastructure development is an impressive story,  we are more interested in whether or not the decision by a producer to take on capacity to reach these markets is a sound one. More to the point, what’s the effect on the long-term prospects of an E&P company in the Marcellus that has taken out substantial pipeline commitments?

To answer the question with an example from history, let’s look at Ultra Petroleum.  Ultra was one of the original shippers on then-Kinder Morgans’ Rockies Express Pipeline. Rockies producers in the late 90’s and early 2000’s are very familiar with the problems faced by Marcellus operators today. Wellhead prices were always discounted to Henry Hub, and tended to crash periodically during low-demand periods. Adding infrastructure was difficult, as large demand centers in the Midwest and on the west coast were hundreds of densely populated miles away. Kinder Morgan’s Rockies Express pipeline was a bold offering, one of the largest capacity gas pipelines to have ever been built in the US up until that point. Using modern pipeline coating technology and a large diameter line, the plan in 2006 was to transport up to 1.5 Bcf/d of gas out of the constrained Rockies to markets in the Midwest as far east as Clarington, OH. Connections with other pipelines along the way would allow access to utility customers in Kansas, Nebraska, Missouri, Illinois, and Indiana.

As a financial calculation, the math was easy. BP, WPX (then Williams), Conoco Phillips, and of course Ultra Petroleum signed up for 10 year terms at $1.65 per MMBtu. This is just the committed (reservation) charge that the producer must pay whether or not the capacity is used. There are also variable costs that in this case were around $0.50 per MMBtu, which are due only when the capacity is used. (These can change often, therefore I’m marking with an estimated charge. This will come into play later). Was this decision justified at the time? Not only had prices delivered to markets in Wyoming and Colorado been depressed, as mentioned above, the forward market suggested continued depressed Rockies basis prices. Here, the difference between what a producer delivering to a citygate in Ohio could expect for his gas, compared to the same producer delivering to a market in Colorado (the red line represents the $1.65 toll on REX pipeline):

Except for a few brief anomalies, the higher-priced market in Ohio more than justified the transportation cost on the new pipeline. Ultra could expect to pay Kinder Morgan and still get a substantial upgrade on their realized natural gas price. So Ultra agreed to buy 200,000 MMBtu/d of transportation rights on the new pipeline at $1.65/MMbtu, for an annual commitment just north of $120 million. If price relationships held as in the past, and Ohio markets were even $3 better than Rockies markets, they could expect to pay for their $1.65 transport plus variable costs (again, keep those in mind), and still potentially get an upgrade of $1 or more per MMBtu on that 200,000 MMBtu/d. A very impressive $73 million per year in incremental revenue. Not shabby at all.

But what happened then?

An unfortunate fact (for our producers) is that deregulated markets with many participants tend to balance themselves. Once a large corridor is open for free flow of commodity from one area to another and constraints are removed, the arbitrage opportunity between the two locations tends to close. In this case, what that means is building a very large pipeline from a producing basin to a market area will tend to collapse the price between the two locations to the marginal cost of transporting the gas that distance. This cost is NOT the $1.65, since that charge is paid to the pipeline no matter what (sunk), but the variable cost of around $0.50, which the producer must pay when the capacity is utilized. It is then this $0.50 charge that determines whether or not the producer chooses to put gas into that pipeline on a given day, or just sell into the local market. Here’s what happened to that same differential after 2009.

After the pipeline began operating, the market did begin to correct and close the arbitrage opportunity.  Ultra and other capacity holders would have to determine on a given day or month whether their chance for an upgrade over selling into the local market was worth the $0.50 of variable cost to flow the gas on the pipeline. This tended to be true in the winters, when the demand for gas in the Midwest spiked and incented capacity holders to pay the variable cost to bring additional supply into that market.

What of the $120 million/year commitment? It became a very expensive ticket to ride. The best Ultra could hope was for demand to surge in Ohio and widen the price spread such that they could pay the variable cost plus recover some fraction of this charge.

Even more frustrating for Ultra: A similarly situated producer who did not commit to Kinder Morgan (such as XOM) would have benefited from the relative upgrade in Rockies gas pricing due to the pipeline’s construction, without the $120 million/year liability.

This became an extreme example, because once Marcellus production began in earnest in 2012, not only could Ultra not cover variable charges and recover some amount of the $1.65/MMBtu, the two price points actually inverted and it made no sense to use the capacity rights at all, making the $120 million per year an irrecoverable cost. In 2013, EBITDA was $335 million, so this charge represented a 35% drag on earnings relative to a competitor without the obligation.

With the exception of the Marcellus supply effect toward the end of the term in question, this is exactly how the deregulated natural gas market is supposed to work.  An oversupply in one area creates depressed prices, which creates a spread to a better market enabling an infrastructure company like Kinder Morgan to propose a project that will cover all the cost of construction and deliver a return besides. Producers will see potential to escape the depressed area  and commit to the project, which will be built, and the arbitrage will close once the constraint is removed and the oversupply in the local market alleviated. Simply put: Transportation contracts on large-scale pipelines built to capture a geographic price differential do not hold value long-term. The REX pipeline became a seasonal “header” system, allowing Midwest gas buyers to draw incremental supply at times of peak demand.

Now, back to the Marcellus and the current situation:

The question now is: How will this play out for producers seeking to escape the new constrained basin? Forward natural gas basis in the northeast says that there are still several years of potential bottleneck before constraints are removed and pricing adjusts. This suggests that price upgrades for transportation holders will continue for the next 2-4 years before turning to a drag on earnings.

Infrastructure projects have attracted a great deal of capital, and are continuing at a respectable pace. By 2018, the flattening of price differentials toward variable cost of transportation tells us that the market expects a free flow of commodity between Appalachia and the Gulf Coast, where Henry Hub is located.

So who will be the Ultra Petroleums of the Marcellus, carrying huge pipeline costs relative to their earnings?

Antero Resources has been one of the more aggressive players in acquiring transportation and announcing their commitments, touting  an advantage over the competition in escaping depressed Appalachian basin pricing. Their press releases tend to include quite a bit of data on their firm transportation commitments. Since we expect transportation to provide a price uplift in the short term and are more concerned with the long term, we’ll look at Antero’s projections for 2016 and beyond. In their recent year-end 2014 releases, management indicated they have no plans at this time to add to the firm transportation portfolio. So we can assume that the 2016 estimates already provided will be accurate.

Here then, are the numbers:

Natural gas : 3.1 Bcf/d of firm gas transportation commitments with an average fixed cost of $0.33/MMBtu for a total annual committed payment to gas pipelines of $373 million. (from year end 2014 investor presentation)

NGL: 71,500 bbl/d of NGL transportation commitments, broken between ATEX and Mariner East pipelines. Antero does not give us a neat weighted average here, but calculating from tariff rates on those pipelines gives an annual total of $100 million in NGL capacity reservation charges.

This adds roughly up to an annual total cost of transportation near $475 million. To put this in perspective, AR’s 2014 revenue was $1.81B.

The expiration of these agreements are staggered between 2018 and 2045, but again management neatly adds it up for us and announces in the 2014 10K filing that the “total contractual obligation under agreements with minimum volume commitments” totals $16 billion over the life of the contracts. Quite a lot for a company with a current $9.26B market cap.

As mentioned above, because the bottlenecks still exist, the transportation commitments are mostly still providing a price upgrade. But it seems already that Antero expects to have costs of transportation over and above what they can use and receive value for. For 2015, production is projected at 1.4 Bcfe/d, and the transportation and sales portfolio consists of 2.25 bcf/d. Management projects that 2015 will bring marketing expense of $100 million to $150 million of unused and/or unmarketed transportation capacity. To put that in perspective, consensus analyst expectations for 2015 are EPS of $0.64, or $168 million. Meaning, in 2015, actual earnings will be reduced by 35% or more due to excess pipeline obligations.

In 2016, when the committed transportation portfolio jumps to from 2.25 to 3.5 Bcfe/d (3.1 gas, 0.4 NGL) of committed transport and expense, the treadmill just runs faster and the unused and unmarketed capacity expense can be expected to grow. Growth in production will mask some of the cost as the pipeline contracts are utilized to bring gas to market and the expense is rolled into the realized price for their gas, but as discussed above, future years will mean less and less value recovered out of the annual $475 million in charges as locational spreads approach variable cost.

Summary: The purchase of transportation rights to move gas and liquids out of oversupplied basins helps producers to capture better netbacks and higher realizations in the short term. In the long-term, however, these benefits are often outweighed by the drag on earnings created by the pipeline fees themselves.